# Global Technology Roadmap for CCS in Industry

Biomass-based industrial CO 2 

# sources: biofuels production with CCS

Michiel Carbo

FEBRUARY 2011 ECN-E--11-012

## Acknowledgments

This Global Technology Roadmap is the collectiv e effort of a large number of organisations. The Norwegian Ministry of Petroleum and Ener gy and the Global CCS Institute funded the project, which was coordinated by UNIDO. The Intern ational Energy Agency supplied most of the
data used in the document. The IEA Gree nhouse Gas R&D Programme and MASDAR provided substantial inputs and MASDAR also hosted first meeting in Abu Dhabi. Five sectoral consultants, Paul Zakkour (CarbonCounts), Jock Brow n (DNV), Duncan Barker (Mott MacDonald), Jean-Pierre Birat (ArcelorMittal) and Michiel Carbo (ECN), wrote the sectoral assessments,
which formed the substantial basis for the road map, and numerous individuals were instrumental in reviewing those assessments. The roadma p was eventually compiled by Heleen de Coninck and Tom Mikunda of the Energy research Centre of the Netherlands.

2 ECN-E--11-012

## Contents

List of tables 4
List of figures 4

1. Introduction 5

2. Current and projected CO 2 emissions 6

3. Industry characteristics 10 3.1 Pulp and paper industry 10 3.2 Biofuels production 11

4. Technical overview of capture options 13
4.1 Ethanol 15
4.2 Fischer-Tropsch Liquids 16 4.3 Substitute Natural Gas (BioSNG) 17
4.4 Methanol to BioDME 18 4.5 Hydrogen 19

5. Estimated costs 20

6. Current environmental legislation and pressures 24

7. Major gaps and barriers to implementation 28

8. Actions and milestones 29

9. References 30

ECN-E--11-012 3

## List of tables

Table 3.1 Capacities and CO 2 emissions of European pulp and paper mills ........................ 10
Table 4.1 Indicative CO 2 capture rates and CO 2 concentrations per source ......................... 15
Table 5.1 Plant capacity, biomass and production cost for different biofuels ....................... 21
Table 6.1 Overview per country of blending mandates, biofuels targets and volumes required ................................................................................................................... 25
Table 6.2 Estimated typical and default values for future biofuels ......................................... 27
Table 8.1 Summary of actions for CCS deployment with biofuels production ....................... 29



## List of figures

Figure 2.1 World biomass use for different scenarios ................................................................ 6 Figure 2.2 Global deployment of CCS in industry and biofuels production in 2020 and
2050 ......................................................................................................................... 7 Figure 2.3 Global deployment of CCS per industrial sector and feedstock in 2020 .................. 8 Figure 2.4 Global deployment of CCS per industrial sector and feedstock in 2050 .................. 8 Figure 3.1 Current and future cumulative global biofuel production according IEA Blue Map low-demand scenario ...................................................................................... 11 Figure 3.2 Cumulative capacities of planned second generation biofuel projects ................... 12 Figure 4.1 Routes to biomass with CO 2 capture and storage ................................................... 13 Figure 4.2 Products from the gas ification of biomass .............................................................. 14 Figure 5.1 Incremental cost of alternative fuels as a function of their CO 2 -equivalent saving potentials at USD 120/bbl ........................................................................... 20 Figure 5.2 The effect of negative emission accounting on total production cost for BioSNG, at a natural gas commodity price of 7.5 €/GJ ........................................................ 22

4 ECN-E--11-012

## 1. Introduction

The biomass industry involves a range of processes that convert a raw biomass feedstock into products such as pulp and paper, sugar, timber and final energy products. Biomass conversion combined with Carbon Capture and Storage (CCS) has the potential to generate useful energyproducts such as electricity, bioethanol, Fischer-Tropsch diesel, substitute natural gas (biomethane) and hydrogen, while removing CO 2 from the natural carbon cycle for geological timescales (Rhodes and Keith, 2003).

Under the most stringent climate change mitiga tion scenarios, an average minimum temperature increase of 1.4 °C is likely to occur during the 21 st century (Van Vuuren et al., 2008). This corresponds to an increase of approximately 2.0 °C in comparison with preindustrial levels. Mitigation scenarios incorporate forcing targets below 3.5 Watt per m 2 , which indicate that CO 2 emissions in 2100 should be lowered by 20-60% with respect to 2000. Modelling suggests that the application of bioenergy with CCS (BECCS) is i ndispensable to in order to achieve deep emission reductions in the longer term, in particular under the most stringent climate change mitigation scenarios (Fischer et al., 2007). The use of CO 2 neutral biomass has the potential to achieve
net removal of CO 2 from the atmosphere when used in combination with CCS. This is important as it allows offsetting historic CO 2 emissions and emissions from dispersed sources. Fossil fuel conversion with CCS typically only mitigates 80 to 90% of the original CO 2 emissions of a source (IPCC, 2005). BECCS technologies involve th e use CCS with the conversion of biomass to electricity or biofuels, or hybrid concepts that can produce both.

BECCS could also facilitate a further reduction ofthe net present value cost for meeting relatively low atmospheric CO 2 concentration stabilization targets, when compared with CCS fromfossil fuels only (Azar et al, 2006). The reduction of added costs appears to become more significant with ambitious atmospheric CO 2 concentration stabilization targets. A general tendency
that can be observed from various stabilization scenarios is that the CO 2 emission abatementthrough the use of biomass grows relatively slowly during the first half of the century, with projected mitigation potentials of up to 7,000 million tonnes CO 2 per year by 2050. While the abatement is expected to increase more rapidly during the second half of the century, with projected mitigation potentials of up to 27,000 million tonnes CO 2 per year by 2100 (Fischer et al., 2007).

The scope of this assessment initially focuses on the conversion of biomass with CCS in the manufacturing industry and biofuels production; not taking into account electricity generation. Recent projections for 2020 and 2050 (IEA 2009b; IEA, 2010) indicate that the contribution of biofuels production with CCS to the combined share of biomass-based CCS in the manufacturing industry and biofuels production is by far th e most significant. Therefore a number of concepts for the production of biofuels with CCS will be discussed more in-depth later during this

assessment.

ECN-E--11-012 5

## 2. Current and projected CO 2 

## emissions

The direct CO 2 emissions in industry amounted to approximately 7,600 million tonnes CO 2 in 2007, this figure involves both process related and fuel combustion emissions (IEA, 2010). The
total CO 2 emissions in the OECD countries are slightly lower than China; while the iron and steel, cement and chemicals sectors almost emit three-quarters of the total direct industrial CO 2 emissions. The IEA BLUE Map low-demand scenario projects a significant increase of biomass use in particular for transportation fuels and power generation, which is displayed in Figure 2.1. The scenario also projects a large contribution fo r transportation biofuels combined with CCS.

Figure 2.1 World biomass use for different scenarios (1 Mtoe = 0.041868 EJ)

The global deployment of CCS is projected to increase from a capture rate of 161 million tonnes

stry and biofuels production sector. CO 2 per year in 2020 to 4,032 million tonnes CO 2 per year in 2050 (IEA, 2010). As depicted by Figure 2, biomass-based production of synthetic fu els and hydrogen with CCS covers 26.3% of the total CCS deployment in the manufacturi ng industry and biofuel production by 2020 and 52.3% by 2050, in accordance with the BLUE Map low-demand scenario.Please note that Figure 2.2 displays the distribution of CCS deployment for both the manufacturing indu

6 ECN-E--11-012CCS in 2020 (161 Mton CO 2 / yr)

Gas (synfuels+H 2 )

2.6% Biomass (synfuels+H 2 )

26.3% Cement
14.0%

Chemicals

17.9%

Pulp and paper
0.7%

Iron and steel
38.6% CCS in 2050 (4,032 Mton CO 2 / yr)

Iron and steel

22.4% Pulp and paper
0.7%

Chemicals

6.6% Cement
13.6%

Biomass (synfuels+H 2 )

52.3%

Gas (synfuels+H 2 )

4.5% Figure 2.2 Global deployment of CCS in industry and biofuels production in 2020 and 2050, based on data obtained from (IEA, 2010)

Figure 2.2 illustrates that the contribution of CCS in the pulp and paper industry only covers a small share of the total projected CCS deployment by 2050. It must be noted that the pulp and paper industry currently consumes the largest biomas s share in industry, 55 out of a total energy use of 190 Mtoe (IEA, 2010), which does not account for biomass use as process feedstock. The
total direct and indirect CO 2 emissions for the pulp and pa per industry amounted 405 million
tonnes CO 2 per year in 2007, and in accordance with the BLUE Map low-demand scenario these are projected to decrease to 175 million tonnes CO 2 per year by 2050 (IEA, 2010). The most important contributions to this reduction are en ergy efficiency improvements, fuel switching and the use of decarbonised electricity.

One of the most important by-products in this industry is black liquor, which is an aqueous solution of lignin, hemicellulose and the spent pulping chemicals used during digestion of wood into paper pulp. Black liquor typically contains roughly half of the energy of the wood going into the digester. The black liquor stream is usually concen trated and is burned in a recovery boiler to generate steam and reclaim the pulping chemic als. The total global black liquor production amounted approximately 215 million tonnes (dry b asis) in 2007, which corresponds to roughly 60 Mtoe (Naqvi et al., 2010).

Numerous studies illustrated that black liquor gasi fication combined with synthesis of transportation fuels could be very suitable for integration with CCS, both from a technological and economical perspective (Möllersten et al., 2003; La rsson et al., 2006; Naqvi et al., 2010; Pettersonand Harvey, 2010). The projected total contribution of CCS combined with black liquor Integrated Gasification Combined Cycle (IGCC) power plants is relatively small at 30 million tonnes CO 2 per year in 2050 (IEA, 2010). The costs for CCS appear similar to coal-fired IGCC with CCS. However, black liquor gasification w ith synthesis of transportation fuels and CCS
has not been taken into account in the latter refe rence. It is recognized that the pulp and paper industry could be an early mover for large-scal e biofuels production with CCS in the EU and North America; and therefore a cost-effective contributor to emission reductions through the implementation of BECCS.

Figure 2.3 and Figure 2.4 illustrate the global deployment of CCS per industrial and biofuels production sector and feedstock in 2020 and 2050, respectively. These figures were compiled under the assumption that the fraction of biomass use as function of the total fuel consumption in a specific industrial sector can projected at th e deployment of CCS in that sector. This approach results in an estimate of both the biom ass-based and fossil fuel-based share of CCS deployment. The projected contribution of biomas s-based CCS amounts 30.6% in 2020, of which

ECN-E--11-012 726.3% accounts for synfuels and H 2 . The projected contribution of biomass-based CCS is expected to increase to 58.8% in 2050, of which 52.3% accounts for synfuels and H 2 . The cement (4.5%), iron and steel (1.1%), chemicals (0.5%) and pulp and paper (0.4%) industries will covera much smaller share of the global CCS deployment, therefore only the production of biomassbased transportation fuels in combination with CCS will be taken into account during this sectoral assessment.

CCS in 2020 (161 Mt CO 2 /yr)

26.3%

36.8% 12.2% 17.4% 2.6% 0.4%

1.7%

0.5% 1.8%

0.3% Biomass (synfuels + hydrogen)

Cement (biomass-based)

Iron and steel (biomass-based)

Chemicals (biomass-based)

Pulp and paper (biomass-based)

Iron and steel (fossil fuel-based)

Cement (fossil fuel-based)

Chemicals (fossil fuel-based)

Gas (synfuels + hydrogen)

Pulp and paper (fossil fuel-based)

Figure 2.3 Global deployment of CCS per industrial sector and feedstock in 2020, based on data obtained from (IEA, 2010)

CCS in 2050 (4,032 Mt CO 2 /yr)

52.3%

21.3% 9.1% 6.1%

0.4%

1.1% 0.5% 4.5% 0.3% 4.5%

Biomass (synfuels + hydrogen)

Cement (biomass-based)

Iron and steel (biomass-based)

Chemicals (biomass-based)

Pulp and paper (biomass-based)

Iron and steel (fossil fuel-based)

Cement (fossil fuel-based)

Chemicals (fossil fuel-based)

Gas (synfuels + hydrogen)

Pulp and paper (fossil fuel-based)

Figure 2.4 Global deployment of CCS per industrial sector and feedstock in 2050, based on data obtained from (IEA, 2010)

8 ECN-E--11-012The increase in biomass use will largely depe nd on the decarbonisation of the biofuels production sector, with a transition from fossil fuels to biofuels. The replacement of natural gas with biomass-derived substitute natural gas (SNG), and an increase demand of hydrogen for heat andpower may also stimulate a growth of the biomass use. In the pulp and paper industry black liquor is a biomass derived residue that is locally av ailable at relatively large quantities, and could be deployed -through gasification- for synthesis of biofuels in combination with CCS.

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## 3. Industry characteristics

3.1 Pulp and paper industry

The production of pulp and paper involves different technologies that are able to convert woodin to pulp; these can be roughly divided in to chemical and mechanical pulping, and combinations of both. Kraft mills use chemicals to de grade the lignin that binds the cellulose fibers; combustion of the lignin compounds (called black liquor) in a recovery boiler allows reuse of
these chemicals. Mechanical mills use grinding and –at some point in the process– steam treatment, this typically results in products that are less sturdy. Paper mills can use a combination of virgin and recycled pulp to produce paper.

Table 3.1 illustrates that for Kraft over 90% of the CO 2 is of biogenic origin, for mechanical approximately 50% and for paper mills less than 20%. The average European Kraft integrated pulp and paper mill emitted 1.2 million tonnes CO 2 , the average mechanical pulp and paper mill
0.23 million tonne CO 2 per year, and the average paper mill 0.17 million tonne CO 2 per year.

Table 3.1 Capacities and CO 2 emissions of European pulp and paper mills (Jönsson and

Mill type Kraft Kraft integrated Mechanical

p Paper 1 Berntsson, 2010)

pulp pulp & paper ulp & paper Mills [no.] 76 21 29 45 Pulp c apacity 9,9 12,320 12,095 14,775 [kADt/year] 2 55

Paper capacity [tonnes/year] - 16,131 22,132 27,169

CO 2 emissions [thousand tonnes/year] Mills [no.] 2 1 29 43 70
Fossil 1,3 3,1 4,7 9,4 91 64 59 20 Biogen ic 2 3 4,308 0,775 5,524 2,217
Total 25,699 33,940 1 1 0,283 1,637

1 Paper mills with capac e 200 thou s es paper pe ere included

he total global CO 2 emissions in the pulp and paper indus try are estimated to amount to 405

ff gases of pulp and paper mills can typically contain up to 13-14% CO 2 , and for Kraft mills ity abov and tonn r year w
2 kilo air dried tonnes (90% dry solids)

T million tonnes per year (IEA, 2010). Roughly two th ird of these emissions originate from Kraft pulp and integrated pulp mills (Jönsson and Berntsson, 2010), and therefore approximately 60%
of the CO 2 emissions of total pulp and paper indust ry are biogenic. During recent years theglobal Kraft pulp production capacity has been growing at a relatively slow rate. The global potential for CO 2 capture is estimated to be 300 to 350 million tonnes at present.

O
most of this CO 2 is biogenic by origin. For Kraft mills retrofit of CO 2 capture could be an option, using chemical absorption similar to post-combustion CO 2 capture. Drastic process integration could potentially reduce the specific en ergy consumption for CCS and the associated capture costs substantially (Möllersten et al., 200 3; Jönsson and Algehed, 2010). For mechanical pulp and stand-alone paper plants integration of CCS appears less viable due to the relatively high cost of capturing small volumes of CO 2
.

10 ECN-E--11-012The estimated global black liquor production obtained from Kraft mills equaled approximately 60 Mtoe in 2007 (Naqvi et al., 2010), while a typical Kraft mill produces 250 to 300 MW th of black liquor (Landälv, 2009). The fleet of recove ry boilers is aging and a large number of boilers are expected to be replaced in the comi ng decade. This could open a window of opportunity for the gasification of black liquor; the latter would allow the synthesis of transportation fuels that have more added value than the production of heat or electricity.



### 3.2 Biofuels production

The current cumulative biofuel production mainly involves the production of bioethanol from sugar cane and grains, and biodiesel from oil seeds. The cumulative global production of these first generation biofuels amounted approximately 2.0 EJ in 2008 (REN21, 2009), as displayed in Figure 5. The production of bioethanol is a well- established industry, particularly in Brazil and the USA with 90% of the global bioethanol prod uction using sugar cane and corn (respectively) as feedstock. Roughly two-thirds of the globa l biodiesel production stems from the European Union, with Germany and France being the largest producers. The feedstock is usually vegetable oil, such as rapeseed or soybean oil.

The 2020 and 2050 projections for the global biof uels production in accordance with the IEA BLUE Map low-demand scenario (IEA, 2010) are al so displayed in Figure 3.1. The total biofuels production is projected to increase to 3.2 EJ in 2020, with a slight increase for bioethanol from sugar cane and the introduction of ligno-cellu losic bioethanol and Fischer-Tropsch diesel. The total biofuels production is projected to fu rther increase to 35.2 EJ in 2050. According to the IEA BLUE Map scenario the production of bioethanol from grains and biodiesel from oil seeds are potentially abandoned, while large incr eases are projected for bioethanol from sugar cane and ligno-cellulosic material, Fischer-Tropsch diesel. It also foresees in the deployment of gaseous energy carriers from biomass, being biogas, BioSNG and hydrogen.

0 5 10 15 20 25 30 35 40

2008 2020 2050Cumulative global biofuel production (EJ) Hydrogen from biomass
Biogas/BioSNG
Biodiesel (Fischer-Tropsch)

Biodiesel (oil seeds)
Ethanol (ligno-cellulosic)

Ethanol (cane)
Ethanol (grains)

Figure 3.1 Current (converted from: REN21, 2009) and future cumulative global biofuel production according IEA Blue Map low-demand scenario (IEA, 2010)

ECN-E--11-012 11Figure 3.2 displays the cumulative capacity ofcurrently known planned second generation biofuel projects; this survey was conducted by IEA Bioenergy Task 39 (Bacovsky, 2010). Thermochemical, bio-chemical and hybrid conversi on cover approximately 60%, 30% and 10%, respectively, of the global second generation biofuel production capacity in 2016. The total foreseen production of second generation bi ofuels in 2016 is roughly 3% of the total biofuels production
in 2008.capacity [t/a]

Figure 3.2 Cumulative capacities of planned second generation biofuel projects (Bacovsky et al., 2010)

The IEA BLUE Map low-demand scenario (IEA, 2010) foresees a contribution of 80% thermochemical and 20% bio-chemical conversion for second generation biofuels production in 2020. The total foreseen production of second generation biofuels in 2020 is approximately 35% of the total biofuels production in 2008. This appears to be a fairly large discrepancy to be covered in just four years; a reason for this could be that the IEA Bioenergy Task 39 survey only includes projects from the respondents to a volunt ary questionnaire. Furthermore a significant amount of demonstration projects are commissioned in the coming two to three years, which potentially could result commercial-scale facilities during the second half of this decade. It is also important to realize that the BLUE Map scenario envisions a certain global energy demand
and CO 2 emissions in 2050, which determines what the deployment of biofuels should be in 2020 to achieve the long-term target.

12 ECN-E--11-012

## 4. Technical overview of capture options

There are a number of routes to convert biomass into final energy products (see Figure 4.1). Forthis roadmap, because of the focus on CCS applications in biofuels production, only the gasification and biological processing routes will be covered.

Figure 4.1 Routes to biomass with CO 2 capture and storage (Rhodes and Keith, 2003)

The replacement of fossil fuels with synthetic fuels that are produced from sustainable biomass readily provides a CO 2 mitigation option. The use of biom ass in biofuel production processes typically also results in high-purity CO 2 by-product streams. In that case the combination of
CO 2 -neutral biomass and CO 2 capture and permanent storage potentially leads to a net CO 2 uptake from the atmosphere, i.e. negative lifecycle emissions.

Bio-chemical biomass conversion processes, for example fermentation, uses living microorganisms to breakdown the feedstock and produce liquid and gaseous fuels. A common 1 st generation process to produce bioethanol, is the fermentation of sugar cane, sugar beet or corn starch, where a by-product of the reaction is a relatively pure stream of CO 2 . The production of liquid ethanol and gaseous CO 2 is almost equal on mass basis. The separation of both compounds isstraightforward since both compounds are present in different phases; hence no additional separation equipment is required. The CO 2 -rich off-gases from the fermentation tanks are dried and compressed to facilitate transport and storage. On a bio-ethanol plant with a net output of 235 million litres per year, the addition of compression equipment only leads to a 0.9% increase in capital costs (Rhodes and Keith, 2003).

Thermo-chemical biomass conversion, or gasificati on, is a thermal treatment that results in the production of gaseous products a nd a small amount of char and/or ash (Demirbas, 2002). During gasification, the biomass or black liquor is c onverted into gases by means of pyrolysis, which occurs at high temperatures of 875-1275 K. To reach these temperatures an oxidizing agent is needed. This can be air or oxygen (Gao et al., 2008). For synthesis of liquid or gaseous fuels itis essential that only a minimum amount of nitrogen is present during the synthesis. This reduces equipment sizes and cost, and increases the pa rtial pressures of the reactants, which typically improves the product yield. This implies that relatively pure oxygen must be employed, typically obtained via cryogenic distillation of air, at significant thermodynamic and economic penalties.

ECN-E--11-012 13Depending on a number of variables such as feedstock characteristics, temperature and gasifying agent, the gas composition consists of carbon monoxide, carbon dioxide, hydrogen, methane, nitrogen, as well as non-gaseous by-products su ch as char and tars. Atgasification temperatures above 1275 K the resulting gas stream consists primarily of hydrogen and carbon monoxide, called synthesis gas or syngas. At relativ ely lower gasification temperatures, other components such as methane and higher hydrocarbons (tars) are also present in the resulting gas stream, and this is often referred to as producer gas.

The gasification of biomass can lead to a number of products, most suitably represented in Figure 4.2, derived from (Smit, 2009). Carbon diox ide is a by-product during all the represented synthesis processes. The employed CO 2 separation technologies are the same as those that are foreseen for pre-combustion CO 2 capture at power plants.

Figure 4.2 Products from the gasification of biomass (Smit, 2009)

Integration of additional separa tion equipment to facilitate CCS is typically not necessary during conversion of biomass to biofuels, either because gaseous CO 2 can be readily separated from the liquid product, or because CO 2 separation equipment is already in place to comply with required product specifications (Carbo et al., 2010a). The CO 2 product stream needs to be dried and compressed to facilitate transport and storage. For both bio-chemical and thermo-chemical biomass conversion routes the additional CO 2 capture costs for dehydration and compression and are estimated to amount 6-12 $ per tonne CO 2 (Dahowski and Dooley, 2008).

The different routes for CCS during biofuel produc tion vary significantly in terms of characteristics and estimated costs. Only capture of process-related CO 2 emissions has been taken into account, since these provide high-purity and often also high-pressure CO 2 streams. Capture from diluted sources, such as an on-site Combined Heat and Power (CHP) unit is financially less interesting, due to the limited scale of the CO 2 source and the heavily diluted flue gas
stream. For this matter four different biofuel conversion routes are desc ribed in more depth: bioethanol through biomass fermentation, as we ll as Fischer-Tropsch liquids, BioSNG, and hydrogen through biomass gasification and subseque nt synthesis. Table 4.1 summarizes indicative
CO 2 capture rates and CO 2 product stream concentration per CO 2 source.

14 ECN-E--11-012able 4.1 Indicative CO 2 capture rates and CO 2 concentrations per source
CO 2 source Carbon in captured high-purity CO 2 concentration in high-

stream 1 T

CO 2 stream/ purity CO 2 Carbon in feed stream [mol%] [mol%]

Ethanol 15-35% ~99%
FT diesel ~50% >95%
BioSNG 40-45% >95%
BioDME ~50% >95% Hydrogen >90% >95%



### .1 Ethanol

Ethanol is currently produced through the bio-chemical conversion of mainly agricultural crops, ugar (sugar cane, sugar b eet, molasses and sorghum) or starch (potato,

la- steps, which are needed to increase the ethanol concentration. Sucrose is

ntly

2 tured and stored. It 

### 4

whi ch contain either s corn, barley and wheat). The starch in the latter crops should be converted to sugars prior to
further conversion.

nversion technology is biomass fermentation followed by a series of distil The predominant co ion and dehydration t extracted from sugar-rich agricultural crops by mechanically pressing the cooked biomass and a subsequent fractionation. Yeast converts the sucr ose which results in ethanol and carbon dioxide as waste products of the metabolism. The ethanol product obtained from the fermentation is diluted with water, which could be removed thr ough distillation up to ethanol purities of approximately 96 wt%. The formation of a low-boiling water-ethanol azeotrope prevents further purification through distillation. This so-called hydrated ethanol is suitable to use as fuel, although not for blends with gasoline. Further purificati on to anhydrous ethanol –which allows blending with gasoline– is established by using molecular sieves that absorb the remaining water content.

The use of starch-based crops requires grain milling or grinding followed by liquefaction and ractionation. The latter steps take place simultane ously during cooking afte r the addition of waf ter. Either enzymatic or acidic hydrolysis is u sed to convert starch to hexose, which can be fermented to produce ethanol and CO 2 as described above. The combined amount of ethanol produced in the US and Brazil was approximately 42 billion liters in 2007 (IEA Bioenergy, 2008). This corresponds to a CO 2 release during the fermentation of 32 million tonnes CO 2 per year in both countries. In the USA the average plant size is about 200 million liters of ethanol per year, which translates to 140 thousand tonnes high-purity CO 2 that could be captured and stored.

Significant R&D efforts are dedicated to the conve rsion of lignocellulosic feedstock into ethanol hrough fermentation. These types of feedstock are typically cheaper and more abunda t available than food crops, although the molecula r structure –and therefore the conversion in to ethanol– is more complex. Lignocellulose consists of cellulose, hemicellulose and lignin; the first two can be converted to sugars and subsequently fermented, although hydrolysis of these compounds typically is more complex than of star ch. Lignin is an aromatic polymer that can not be fermented and is typically combusted to generate heat and/or electricity.

Based on the initial carbon content of the sugars that are fermented in a bioethanol plant 67% of he carbon leaves as ethanol, and 33% as high-purity CO that could be cap t must be noted that the distribution of carbon in the outlet streams of the entire plant can vary significantly with different feedstocks and plan t configurations, for example by combustion of lignin in a combined heat and power unit in a lignocellulosic bioethanol plant.

1 After dehydration

ECN-E--11-012 15One of the first commercially operated ethanol pl ants integrated with CCS, and thus biomassbased industrial CO 2 capture and storage project, started operation in the U.S.A . during the third

uarter of 2009 (Chaparral Energy, 2010). At present approximately 60% (170-180 thousand

lon tonnes CO over three years in the Mt. Simon Sandstone saline formation. The CO is oblant in Sao Paolo state, Brazil (GEF, 2010). For a typical sugar mill size in Sao Paolo state of

version of lignocel- by gas cleaning, Fischer-Tropsch synthesis and rer opsch liquid products are diesel and kerosene.

sch ynthesis. Furthermore, high temperatures reduce the tar concentration in the produced synthesis

moval prior to further synesis. Entrained flow gasification requires biomass pre-treatment to allow high-temperature

d catalysts , cobalt-based catalysts display no activity for e water-gas reaction and therefore the H /CO-ratio should be corrected upfront by a separate

e from methane to heavy waxes. The process is also highly exothermic nd adequate heat removal is required to cont rol the desired product specification. Cobalt-based q tonnes CO 2 per year) of the total produced CO 2 is captured at the Arkalon bioethanol plant in Liberal, Kansas, and transported to an oil field near Booker, Texas, for enhanced oil recovery.

A similar pilot project in the U.S.A. is mana ged by the Midwest Geological Survey Consortium and started operation early 2010 (MGSC, 2010). Th is project foresees the injection of 1.0 mi
li 2 2 tained from the Archer Daniels Midland Company (ADM) bioethanol plant in Decatur, Illinois.

The Global Environment Facility (GEF) of the United Nations Development Programme (UNDP) awarded a grant for implementation of CCS at a sugar fermentation-based ethanol

p 25 million liters of ethanol per year, this implies that 20 thousand tonnes of CO 2 per year will be stored in a local saline formation. Implementation is foreseen in early 2012.



### 4.2 Fischer-Tropsch Liquids

The production of Fischer-Tropsch liquids involv es the thermo-chemical con
lul osic biomass into synthesis gas, followed fining to the final product. Typical Fischer-T

High-temperature biomass gasification technologies result in a synthesis gas that primarily consists of hydrogen and carbon monoxide, which are two primary reactants in Fischer-Trop

s gas. Two types of gasifiers that are suita ble for synthesis gas production with high H 2 and CO concentration can be distinguished: pressurized fluidized bed and entrained flow gasifiers (Higman and van der Burgt, 2008). Both use oxygen obtained from an Air Separation Unit (ASU), to minimize the nitrogen c oncentration in the synthesis gas.

After fluidized bed gasification roughly 5% of the carbon ends up in the ash, while the synthesis gas contains a moderate amount of tar that requi res conversion or re
th gasification. Pre-treatment can occur through torrefaction, which involves biomass upgrading though a mild heat treatment (250-300 °C) that increases the heating value, reduces the moisture content and eases milling (Gerhauser et al., 201 0). Another pre-treatment method involves biomass pyrolysis, which involves a moderate heat treatment (450-550 °C) that results in a pyrolysis oil slurry and char. The Carbo-V concept by Choren is commercially available and includes pyrolysis of biomass at moderate temperature and subsequently high-te mperature (> 1300 °C) conversion of the pyrolysis oil to synthesis gas, while the char is added and converted in a secondary quench step (Rudloff, 2010).

Two types of catalyst are commercially used for the Fischer-Tropsch synthesis: iron- and cobalt-based catalysts. Unlike iron-base
th 2 water-gas shift reactor. Before the Fischer-Tropsch synthesis, CO 2 and other trace impurities are selectively removed in the acid gas removal section. The absence of CO 2 during the FischerTropsch synthesis improves the yield. CO 2 is separated using commercially available absorption technologies, and upon regeneration of the liquid solvent a high-purity CO 2 stream is available for capture and storage.

Fischer-Tropsch synthesis produces a range of pr oducts, which depending on the operating conditions and catalyst, rang

a

16 ECN-E--11-012catalysts are commonly used in fixed reactors, while iron-based catalysts are commonly used in slurry reactors. Saturated steam is generated in the reactor to maintain appropriate temperature levels. After the Fischer-Tropsch synthesis the g aseous products are separated and either used to generate electricity, or these are fed to an auto thermal reformer to produce synthesis gas that is fed back to the gasification outlet stream. The liquid products are distilled to produce the final products and a heavy fraction; the latter undergoes an additional hydrocracking step to increase the final product yield.

A Fischer-Tropsch liquids plant based on an oxygen-blown CFB gasifier emits roughly 5% of the initial carbon input as CO 2 in the flue gas of the combined heat and power unit, 6% in the

har, 37% in Fischer-Tropsch liquids and 52% as high-purity CO 2 that could be captured and

of 45 MW th and an output of 18 million liter fuel. Wood chips are onverted in the Carbo-V gasifier; the synth esis gas is cleaned, conditioned and led to the

ass, folpression, the methane-rich product stream

n producer gas should be obtained from the asifier, since the absence of n itrogen facilitates compliance with specifications for injection in

d combustion reactor engtsson, 2007). The first reactor uses steam fo r fluidisation and typically yields high initial

condense at temperares below 400°C, and cause equipment fouling and plugging. The carcinogenic nature of tars c stored (Carbo et al., 2010a).

The first commercial biomass-to-liquids plant is the Choren Beta plant in Freiberg, Germany, (Rudloff, 2010) with an input

c Fischer-Tropsch synthesis. Commercial ope ration is expected to start late 2010.



### 4.3 Substitute Natural Gas (BioSNG)

BioSNG is produced through the thermo-chemical conversion of lignocellulosic biom
low ed by gas cleaning and methanation. After com could be injected in any existing natural gas grid.

One of the most important aspects during the desi gn of a bioSNG plant is the selection of the appropriate gasification technology. A nitrogen- lea

g high-pressure natural gas grids. This requireme nt leaves three possible biomass gasification technologies: oxygen-blown pressurised Entraine d Flow (EF), oxygen-blown pressurised fluidised bed (both BFB and CFB) and steam/air-blown indirect gasification at atmospheric pressure. The net biomass-to-bioSNG efficiency on LHV-basis for these technologies amount 54.3%, 58.1% and 66.8%, respectively (van der Meijden et al., 2010). The net efficiency for indirect gasification based bioSNG plants is significantly higher since this configuration does not requirea capital and energy-intensive Air Separation Unit (ASU). Oxygen-blown BFB and CFB biomass gasification are more developed than in direct gasification at present. However, forBioSNG production the focus will be on indirect gasification, since this technology has a significantly higher yield and is expected to mature during the next decade.

Indirect gasification concepts typically consist of two reactors: Biomass pyrolysis takes place in the first reactor by heated bed material obtained from the secon (Bmethane concentrations in the producer gas stream, due to the moderate gasification temperatures (800 – 900°C). The carbon conversion in the first reactor is typically 80 – 90%; the unconverted fraction is combusted in the second ai r-blown fluidised bed combustion reactor, to pre-heat the bed material prior to feeding it b ack to the pyrolysis react or. The use of bed material for heat transfer between both reactors limits the operating pressure to approximately 7 bara (van der Meijden et al., 2010). At significantly higher pressures the gaseous volume becomes too small to provide sufficient transport of bed material for heat transfer.

An important disadvantage of gasification at m oderate temperatures is the formation of tars (Milne et al., 1998). Tars are higher aromatic hydrocarbons that typically

tu also poses strict handling implications from a safety and environmental point of view. Thermal or catalytic cracking of tars is undesirable, since these technologies are expected to reform a significant part of the methane content in the producer gas. Oil-based scrubbing appears more

ECN-E--11-012 17appropriate since tars are rem oved above the water dew point te mperature, which avoids contamination of water with tar compounds. After regeneration of the scrubbing oil these tars can be fed back to the combustion reactor of the indirect gasifier.

After tar removal, unsaturated hydrocarbons ar e hydrogenated, sulphurous and chlorine components are removed and CO 2 is separated. The latter takes pl ace using commercially available

atural gas sweetening technologies (absorption), to provide a product gas with the appropriate

iel d in the methanation section. ownstream of the methanation reactors, the prod uct stream primarily consists of methane and

ki et al., 2010), while water-gas shift, CO 2 separation and methanation techologies are commercially available and have been proven downstream of coal gasification apE.ON. The first phase comprises a 20 MW th ioSNG plant to be operational in 2012; it will be constructed in Göteborg, Sweden. For this

downstream of the same gasification e Fischer-Trops ch liquids section of this assessment. The -gas shift reactor, with H 2 S and CO 2 removal positioned

e mature market for DME as transportaon fuel (Clausen et al., 2010).

nd operates at a pressure of 30 bar. From 2010 2012 a BioDME pilot plant will be operated downstream of the gasifier as part of the EU FP7 n stoichiometric composition of H 2 , CO and CO 2 . A near pure CO 2 stream will be available upon regeneration of the absorption liquid, which can be compressed to facilitate transport to the CO 2 storage site. Traces of CO 2 that are not separated will be c onverted to methane in the methanation section. Commercially offered methanation pr ocesses are based on a sequence of fixed-bed
reactors with intermediate cooli ng; the catalyst is nickel-based.

Gasification in indirect gasifiers typically takes place at relatively low pressure; hence the cleaned producer gas is compre ssed to increase the methane y
D water with traces of hydrogen and carbon monoxide. An interesting feature of a bioSNG plant is the net production of water, in contrast to fo ssil fuel power plants with CCS. The produced water is removed during bioSNG upgrading, and is therefore relatively clean which eases waste

water treatment.

Dedicated biomass gasification and gas cleaning t echnologies are still under development at this stage (Kopyscins

nplications. A BioSNG plant based on indirect gasification emits roughly 20% of the initial carbon input as CO 2 in flue gas, 40% as methane in BioSNG and 40% as high-purity CO 2 that could be captured and stored (Carbo et al., 2010a).

The largest commercial BioSNG project is the Göteburg Biomass Gasification Project, GoBiGas, which was initiated by Göteborg Energy and
b plant an indirect FICFB gasifier will be depl oyed with Haldor Topsøe’s TREMP fixed bed methanation technology downstream (Mastrup, 2010). The second phase involves an 80 MW th SNG plant, which is scheduled to be operational by 2016.



### 4.4 Methanol to BioDME

The methanol to BioDME synthesis is typically positioned

tec hnologies as described under th
H 2 /CO-ratio is adjusted in a water downstream. The methanol yield in a single react or can be relatively high, although a recycle or a second reactor is required to further increase the yield and reduce by-product formation. Any remaining by-products will be sepa rated prior to the DME synthesis, which converts two ethanol molecules to one molecule dimethyl ethe r and one molecule wate r (Landälv, 2009). Any unconverted methanol is recycled or sold as by-product.

An interesting feature of a BioDME plant is the opportunity for co-production of methanol and DME, which could be used to bridge the gap to a mor ti

Chemrec has operated a 3 MW th oxygen blown black liquor gasifier at Piteå, Sweden (Landälv, 2009). This pilot facility was started up in 2005 a

to BioDME project. This project foresees the production of 4 tonnes DME per day, which will be used for field tests with 14 trucks. This project is coordinated by Volvo.

18 ECN-E--11-012A larger commercial project is foreseen in Domsjö, Sweden. This project involves a 200 MW th Chemrec oxygen blown black liquor gasifier, and the downstream sy nthesis of 450 tonnes

ethanol per day or 300 tonnes DME per day. The final investment decision for this project will

gasoline project 

### (Mastrup, 2010) . This ilot plant will be installed downstream of the Carbona gasifier at GTI in Des Plaines, Illinois,

ids section of this assessment. The water-gas shift reaction however, quence of reactors with intermediate cooling, to maximize the carbon m be made late 2011, while start-up is scheduled in 2013.

In parallel to the above mentioned methanol to BioDME projects, the U.S. Department of Energy awarded a 25 million USD grant for a methanol to

p which processes 20 tonnes of wood per day corr esponding to an input of roughly 5 MW th

.



### 4.5 Hydrogen

The hydrogen production in principal uses the sa me gasification technologies as described under
the Fischer-Tropsch liqu likely takes place in a se monoxide conversion to hydrogen. CO 2 and trace impurities will be selectively removed in the acid gas removal section, using commercially av ailable absorption technologies. The resulting hydrogen-rich stream still contains traces of CO and CO 2 , therefore this stream is further purified in a Pressure Swing Adsorption (PSA) unit. The bulk of the initial carbon input can be captured as pressurized high-purity CO 2 , being roughly 80 t0 90%. Part of the carbon is captured in the char or slag (depending on the gasifier type) and the PSA off-gases.

To the knowledge of the author no commercial demonstration plants for the production of biobased hydrogen are either in operation or planned at present.

ECN-E--11-012 19

## 5. Estimated costs

Cost data for biomass-to-biofuel conversion pr ocesses are scarce, in particular for conversionprocesses combined with CCS. The most important reason for this is that BECCS forms a relatively new field in research a nd development. Plants for th e production of second generation biofuels are still relatively small in size, up to the commercial demonstration phase, which could result in less accurate cost figures.

Typically the capital investment of biomass conversion plants is higher than for fossil fuel conversion plants. This is mainly attributable to the nature of biomass: the energy density is usually lower than for instance coal, the moisture conten t higher and the composition of biomass is less homogenous and more fibrous. Therefore more equi pment for biomass pretreatment is required in comparison with coal and natural gas. Large-s cale import of biomass is expected to result in higher prices on an energy basis than for fossil fu els, which also contributes to higher prices for
biofuels.

These phenomena can also be observed in Figure 5.1. This figure displays the incremental cost
and lifetime well-to-wheel CO 2 savings for various synthetic fuels and biofuels using conventional gasoline as a reference (without accounting for negative CO 2 emission reduction through BECCS). The incremental cost for biomass-to-li quids (BTL) in comparison with gasoline is roughly zero, while the cost significantly decreases for CTL despite of the relatively high CO 2 emissions.

Figure 5.1 Incremental cost of alternative fuels as a function of their CO 2 -equivalent saving potentials at USD 120/bbl (IEA, 2010) Note 1: Negative CO 2 -eq savings means the use of the fuel results in higher WTW CO 2 -eq emissions than using gasoline. Note 2: Assumes oil priced at USD 120/bbl. Costs reflect a bottom-up technol ogy cost analysis of making each fuel, including feedstock production, tr ansport, conversion to fuel, fuel transport, storage and retail supply to vehicles. Note 3: Natural gas and Bi oSNG are assumed to be widely used in different end uses, sharing the costs of the transmission and distribution infrastructure required.

20 ECN-E--11-012An overview of reported biofuel production plan t capacities and associated biomass and biofuel production costs is provided in Table 5.1. A large share of the production cost comprises the biomass cost. It must be noted that the reported figures should be divided by the plant efficiency to provide the actual share of biomass cost as pa rt of the production cost. An additional complication is that only a few studies report the in tegration opportunities for CCS, although these are often not substantiated by cost figures, such as CO 2 capture or avoidance cost.

Table 5.1 Plant capacity, biomass and production cost for different biofuels

ody biomass) Range Ethanol Hamelinck Solomon et Eriksson & (from wo & Faaij al. Kjellström
2006 20 07 2010 Plant capacity (MW th , in ) Not spe 295-400 400 cified 295 Biomass cost (€/GJ) 3.0 Not specified 3.5 3.0-3.5 Ethanol cost (€/GJ) 2 2 19.7-2 18 2.0 18.7 1.5 .7-22.0

Fischer-Tropsch Yamashita Hamelinck Kreutz et al. Van Vliet et Range
et al. & Faaij al.
2004 2006 2008 20 09 Plant capacity (MW th , in ) 400-660 430 400 660 400 Biomass cost (€/GJ) 1.5 3.0 3.8 1.8 -4.6 1.5-4.6 FTL cost (€/GJ) 2 13.8-2 1 2 18 13 0.8 8.0 1.5 .0-48.5 .8-48.5

BioSNG Gassner & Åhman Carbo et al. Hacatoglu Range
Maréchal et al.
2009 2010 2010b 2010 Plant capacity (MW th , in ) 100-500 150 100 500 400 Biomass cost (€/GJ) 9.2 4.5 4.0 2.8 2.8-9.2 BioSNG cost (€/GJ) 2 16.4-2 6.9 2 1 1 13 0.0 3.3 3.1 .1-26.9

BioDME RENEW Larsson et Clausen et Range
al. al.
2008 20 20 08 10 Plant capacity (MW th , in ) 3 479 479-2,302 500 -601 2,302 Biomass cost (€/GJ) 5.1 -7.8 0.9-1.9 4.6 0.9-7.8 BioDME cost (€/GJ) 2 16 7 1 7 .1-21.0 .6-12.8 1.9 .6-21.0

H ydrogen Hamelinck Sarkar & Range & Faaij Kumar
2006 2010 Plant capacity (MW th

, in ) 400-456 400 456 Biomass cost (€/GJ) 3.0 2.2 2.2-3.0

H 2 cost (€/GJ) 2 1 7 6.0 7.5 .5-16.0

1 Exchang e rates: EUR/USD: 1 ; EUR/SEK: 1.0:9.5

he incremental cost of CO 2 capture in case of biomass-to-bio fuel conversion processes is gen- .0:1.3

2 Production cost

T erally low, since a high-purity CO 2 stream is readily available for capture. The incremental capture costs are therefore limited to CO 2 dehydration and compression, and typically only amount 6-12 $ per tonne CO 2 , mainly depending on the CO 2 transportation pressure.

ECN-E--11-012 21D uring the calculation of the total CO 2 avoidance cost, the price difference between a biofuel

he production of BioSNG illustrates what the effe ct would be of the inclusion of negative

igure 5.2 demonstrates the effect of the incl usion of negative emission accounting for BioSNG.

he inclusion of negative emission accounting results in decreasing BioSNG production cost at and its fossil fuel counterpart is also take n into account. The IEA Blue Map low-demand scenario foresees gradually decreasing fossil fuel co mmodity prices in the long-term as a result ofreduced demand; since a significant part of the demand will be fulfilled with biofuels. This scenario also foresees much higher effective co mmodity prices due to the inclusion of a CO 2 price of 175 USD per tonne CO 2 in 2050.

T emission accounting for the synthesis of biofuels with CO 2 capture and storage. During the production of BioSNG through indirect gasification the total carbon content of the inlet stream is distributed over the following outlet streams: 40% as BioSNG, 40% in high-purity CO 2 stream and 20% as flue gas which is vented. The net greenhouse gas emissions on plant level are presumably almost zero.

F Starting points are the lower and upper boundary of BioSNG production cost with no CO 2 price in place, representing an N th plant and a first-of-a-kind plant, respectively. A natural gas commodity price of 7.5 € per GJ was assumed, while the combustion of natural gas results in a CO 2 emission of approximately 55 kg CO 2 per GJ if life cycle CO 2 emissions are omitted for the sake of simplicity.

T increasing CO 2 prices, and provides an incentive to impl ement CCS. The use of natural gas is also expected to result in increasing costs when CO 2 prices increase. This further reduces the price gap between natural gas and BioSNG. The total CO 2 avoidance cost for an N th BioSNG plant with CCS and inclusion of negative emis sion accounting therefore amounts approximately 60 € per tonne CO 2 , and 205 € per tonne CO 2 for a first-of-a-kind plant with CCS.

0 5 10 15 20 25 30

0 50 100 150 200 250

CO 2 price [EUR/ton CO 2 ]Fuel Cost [EUR/GJ] BioSNG with CCS @ 26.9 EUR/GJ

BioSNG with CCS @ 13.0 EUR/GJ

Natural Gas @ 7.5 EUR/GJ

Figure 5.2 The effect of negative emission accounting on total production cost for BioSNG

ce (range 13.0-26.9 EUR/GJ according to Tabl e 3), at a natural gas commodity pri of 7.5 €/GJ

22 ECN-E--11-012It is apparent that the total CO 2 avoidance costs will increase at lower natural gas commodity prices. If the CO 2 price gradually increases to 175 USD per tonne CO 2 in 2050 (CO 2 price as suggested by the IEA Blue Map scenario) and ne gative emissions would not be accounted for, the broad implementation of BioSNG to replace natural gas will take place much slower. The latter would imply that the total CO 2 avoidance cost for an N th BioSNG plant with CCS would amount approximately 100 € per tonne CO 2 . The total CO 2 avoidance costs associated with other biofuel types display similar tendencies wh en it comes to the inclusion of negative emission accounting.

ECN-E--11-012 23

## 6. Current environmental legislation and pressures

The production of biofuels is inherently de pendent on the demand for biofuels. For environmental and energy security reasons, several countries around the world have implemented policies and measures to enhance the use of biofuels . Initial biofuel policies mainly pursued blending of bioethanol and biodiesel with their fossil equivalents (IEA Bioenergy, 2009a). These policies mainly involved obligatory measures as we ll as tax breaks and subsidies. Since then policies gradually expanded towards flexible vehi cles that are able to run on a range of fossil/biofuel blends, and the introduction of fuel standards for bioethanol and biodiesel. Moreover, overall biofuel targets and minimum an nually required volumes were set.

There are a number of regions in the world that have taken steps to encourage the use of biofuels in transportation fuels, primarily through ma ndating a certain percentage of biomass-derived
fuel to be blended with conventional fossil fuel s. Policies which mandate ethanol blending, currently in Brazil and the US, have been designed for the purposes of energy security rather than
efforts to reduce CO 2 emissions from transport. Policies primarily involve promoting 1 st generation biofuels, which in addition to exhibiting variable greenhouse gas emission savings of between 20% to 70%, (Concave, 2008), have been criticized on various aspects from effecting grain and livestock prices, to the greenhouse gas emissions stemming from land-use change for
biomass cultivation.

Table 6.1 provides an overview of blending manda tes, biofuel targets and required volumes per country. The non-OECD nations that have established biofuel policies are generally countries that either produce biofuels or biofuel feedstock. The main driver for developing these policies is usually energy security as opposed to climat e change mitigation. Other countries did not mandate blends; define targets or required vol umes, but created incentives to increase the biofuel production, such as Mexico, Guatemala, El Salvador Malaysia and Indonesia.

24 ECN-E--11-012Table 6.1 Overview per country of blending mandates, biofuels targets and volumes required (Jank et al., 2007; Bringezu et al., 2009; Jumbe et al., 2009; Eisentraut, 2010) Blending mandates Biofuel targets Volumes required per year
Bioethanol Biodiesel Biofuels total Bioethanol Biodiesel Argentina E5 B5
Australia Belgium 5.75%
Bolivia B20 (2015)
Brazil E22-E25 B5 (2013)
Canada E5 B2 (2012)
China E10 (9 provinces) 13 bl (2020)
Columbia E10 B5 2.5 bl (2013)
Croatia 5.75%
Dominican Rep. E15 (2015) B2 (2015)

EU Total 10% (2020)

France 10% (2015) Germany 12-15% (2020) 1.45 (2020) 8.3 (2020)
Ghana 20% (2015)
India E10 (13 states) B5 (10 states) 2.3 bl (2020) Italy E1 B1 Japan 5% (2030) 6 bl (2030) Malaysia B5
New Zealand 3.4% (2012) Paraguay B5

Peru E7.8 B5 Philippines E10 (2011) B2 (2011) Portugal 10%
South Africa 4.5% (2013)
Thailand E10 B5 (2011) 10% (2012)
UK E5 B5 Uruguay E5 (2014) B5 (2012)
USA 20% (2022) 130 bl (2022)

Brazil is the country with the most long-standing biofuel policy, aimed at mainly producing bioethanol from sugarcane, for which the country h as excellent climatic conditions. The rationale was mainly energy security and foreign currency concerns in the 1970s, when petroleum prices soared (IEA Bioenergy, 2009b). The policy empl oyed was a combination of public (including World Bank) and private investment in the sugar cane plantation area and a subsidy on the use of bioethanol. The subsidy, which reached 2 b illion USD in 1996/1997, was complemented by a renewable fuel standard of ethanol in petrol (and more recently of biodiesel in diesel, based on soybean as a feedstock). Already in the 1980s, a significant number of vehicles produced in Brazil ran on pure ethanol. Starting in 2003, the fa vourable market conditions for biofuels led to the adaptation of vehicles that are suitable for both fossil- and bio-based fuels, the so called flexcars (Pelkmans et al., 2008).

Brazil is also the world’s largest exporter of bi ofuels, mostly to the United States, Europe, Korea and Japan. While export markets are still grow ing, Brazilian companies continue to build new ethanol plants. With an almost 25,000 million litre production of bioethanol in 2008, the high-purity CO 2 emissions of these ethanol plants could amount to an estimated 19 million tonnes CO 2 per year.

Accepting the limitations of 1 st generation biofuels, the US Re newable Fuels Standard (RFS) has mandated the blending of 2 nd generation biofuels from 2010 onwards. The US has previECN-E--11-012 25ously had strong policies to support ethanol production from corn, but with the enactment of the RFS, further increases in biofuel production in the next decade is exp ected occur through the
use of 2 nd generation biofuels. Production of 2 nd generation biofuels in the use are expected to increase from current negligible amounts to 60.6 b illion liters per year in 2020, out of a total predicted biofuel production of 136 billion liters per year.

An alternative for the policy measures addressed in Table 4 is the introduction of low-carbon
fuel standards. These standards aim at the reduction of the overall lifecycle CO 2 emissions of transportation fuels. A reduction target is defi ned and fuel providers can choose their preferred
method to reduce CO 2 emissions, such as biofuel blending, increase refinery efficiencies, capture and storage of CO 2 during production, and buying credits from other parties. Low carbon
fuel standards are seen as more flexible than most of the other policy measures at moderate abatement costs. However, an important disadva ntage is that fuels could be obtained from unregulated markets or the fuel production could be shifted, which subsequently could hamper the energy security and result in CO 2 leakage (Yeh and Sperling, 2010).

Low-carbon fuel standards are being employed in the US RFS and the European Union Renewable Energy Directive (EU RED) and involve the establishment of a minimum GHG emissions saving of a biofuel compared to its fossil fuel equivalent. The EU Directive mandates member states to enact policies that en sure that second generation biofuels account for a 10% share in gasoline and diesel consumption by 2020. This mandate is supplemented by the introduction of a biofuel ‘sustainability criteria’. Part of the su stainability criteria, covers the minimum emissions saving to be achieved by biofuels, compared to the gasoline or diesel fuel it replaces. The minimum requirement for emissions savings is 35% from 2013, rising to 50% by 2017 and 60% by 2018. These mandated emissions savings are comparable to the requirements under the US RFS, which states that lifecycle GHG emission savings for 2 nd generation (cellulosic) biofuels must be 60%, and 50% for biomass-derived diesel 2

.

Of particular interest to the incentives for appli cation of CCS in biofuel production, in the EU RED calculation methodology for the GHG emissions from the production and use of biofuels and bioliquids, the emissions saving through CCS can be subtracted from the total emissions from the use of the fuel. The typical and defa ult greenhouse gas emission savings for various biofuel production pathways are presented in Ta ble 6.2. However, given that the future 2 nd generation biofuels are expected to be able to r each GHG emissions savings of up to 95% compared to fossil fuels, it is unclear whether the minimu m emissions savings requirements set by the US and EU legislation will warrant the application of CCS for compliance purposes.

2 Compared to the average baseline em issions of gasoline and diesel in 2005.

26 ECN-E--11-012Table 6.2 Estimated typical and default values for future biofuels 3 (EU, 2009)

3 Not net carbon emissions from land-use change

ECN-E--11-012 27

## 7. Major gaps and barriers to implementation

CO 2 capture and storage from biomass-based indus trial sources is a mitigation technology that only receives little interest at present. The 4 th assessment report of the IPCC (Fischer et al.,2007) recognized BECCS as a technology that could potentially be the key in pursuit of low atmospheric CO 2 concentration stabilization levels. Howe ver, the combination of biomass conversion with CCS generally tends to be overlooked by the biomass-ba sed industry, biofuels production sector and CCS communities. From the pers pective of the biomas s community the acceptance of CCS is generally low, while the focus of the CCS community is on the use of fossil fuels specifically tailored for electricity genera tion with CCS. Consequently, the number of research papers on biomass conversion with CCS to date only amount approximately one hundred. Furthermore, the technology lacks industr ial supports to pursue broad implementation, while there is a lack of awareness amongst policy makers.

Even though the 2006 IPCC Guidelines for Na tional Greenhouse Gas Inventories allow for negative emissions to be allocated in nati onal GHG inventories (IPCC, 2006), the concept has yet to be transposed into current policy frameworks (IEA, 2009b). An example of that is thethird phase of the EU Emission Trading System, where the potential inclusion of biomass conversion only involves biomass co-firing during electricity production. Installations that exclusively 4 use biomass as process input stream are exclud ed from the system. This allows the emission of CO 2 without fiscal penalties, although it does not result in financial benefits since CO 2 credits are not allocated to these installations . The exclusion from the EU ETS has the potential to encourage bio-based industries; however the policy does not recognize the potential of achieving ‘negative emissions’ through combina tion of CCS with biomass conversion processes. In order to incentivize CCS in biomass-based industries, operators that capture and store
CO 2 must be effectively credited for doing so.

Currently CO 2 capture and storage in general is not creditable under the Kyoto Protocol’s Clean Development Mechanism (CDM) due to issues around certainty of storage in a temporally constrained crediting mechanism. This has the consequence that the CO 2 capture and storage from biofuel production also cannot benefit from the carbon price in the CDM. An additional gap for developing nations could be that the subsurface CO 2 storage potential is generally mapped to a lesser extent in comparison with developed nations.

4 97%

28 ECN-E--11-012

## 8. Actions and milestones

The actions necessary to improve the deployment of CCS with biofuels production must be viewed from a broader perspective of demand for alternative transport fuels and energy carriers.
In distinction between the other sectors covere d in the UNIDO Global Technology Roadmap for CCS in Industry, the biomass-based sector is sm all and underdeveloped. Demand for biofuels, biogas and other biomass derived products is currently slight, effectively suppressed by conventional fuels such as gasoline, diesel and natural gas which still dominate the market. Furthermore, the technologies to produce biofuels from bio tic feedstocks that are less likely to compete with food supply, termed 2 nd generation biofuels, are at presen t in development and demonstration stages. Nevertheless, the IEA BLUE Map scenario states that reducing global CO 2 emissions by 50% by 2050 will require an intensification of biofuel production, and substantial application of CCS within this emerging sector. An overview of actions is provided in Table 8.1.

Table 8.1 Summary of actions for CCS deployment with biofuels production

ACTIONS
Research

• Researc h conducted to develop methods for the inclusion of negative emissions in exi sting policy mechanisms, such as the EU ETS

• Research conducted to analyze the impact that negative emissions could have on the
g lobal carbon market

• Continued research int o biomass-to-liquid technologies, the gasification of biomass for
t he production of 2 nd generation biofuels

• Research networks established

Technological development

• Demonstration activities and s cale-up of biomass gasification to continue

• Demonstration plant for gasification of biomass with CCS by 2015

• Expansion of demonstration plants for bioethanol production with C CS

Policy

• Polici es that increase the demand for biom ass-based products must continue to by i mplemented in developed and developing countries

• Biomass with CCS must be recognized by governmen ts as a potential cost-effective

a batement option, and incorporated into future policies relating to CCS deployment in general

• A BECCS stakeholder network should be formed , to facilitate more effective lobbying f or the technology

O ne of the first actions to be undertaken in the near future is the formation of a BECCS stakeeanwhile, more detailed scientific studies are needed on costs, long-term contribution on

achieve a substantial contribution of biomass-based industrial CO 2 capture and storage by 2050. holder network. This requires mobilization of a ll relevant entities: policy makers, NGO’s, scientific community and industry champions. The involvement of bodies such as the IEA, UNIDO
and GCCSI is considered to be essential in the fo rmation of such a network. Other early movers
are nations that could have a short-term interest in application, such as Brazil, Sweden, the USA
and Indonesia. This network increases awarene ss amongst stakeholders and potentially facilitates the establishment of policies aiming at BECCS deployment.

MGHG reduction and early opportunities. Furthermore a dedicated BECCS pilot and demonstration programme should be facilitated by policy ma kers. All the above measures are required to

ECN-E--11-012 29

## 9. References

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from biomass. Bengtsson, K., 2007, “Twin-bed gasification con cepts for Bio-SNG production,” Lund Institute of Technology, Department of Chemical Engineering, Lund, Sweden. Bringezu, S., Schütz, H., O’Brien, M., Kauppi, L., Howarth, R.W. and McNeely, J., 2009, “Towards sustainable production and use of res ources: Assessing biofuels,” United Nations Environment Programme (UNEP), Paris, France. Carbo, M.C., Smit, R. and Drift, A. van der, 2010a, “Bio Energy with CO 2 Capture and Storage (BECCS): conversion routes for negative CO 2 emissions,” Proceedings of the 4 th International Freiberg Conference on IGCC & XtL Technologies, Dresden, Germany, 3-6 May,
2010. Carbo, M.C., Smit, R., Drift, A. van der and Jansen, D., 2010b, “Bio Energy with CCS (BECCS): Large potential for bioSNG at low CO 2 avoidance costs,” Proceedings of the
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